Abstract
In order to ensure adequacy of generation supply, the utility industry has traditionally been required to carry two to three years of planning reserves, e.g., 20 percent over projected peak demand. Closely related, they have often used two-part (capacity/energy) pricing to buy and sell generation (real power) output. This paper argues that continued use of this approach, especially continuing to require planning reserves under power pool or NERC or other mandate, will undermine the benefits of power industry restructuring. In contrast, a market with no administered capacity requirement, but a one-part commodity price reflecting both marginal operating costs and capacity scarcity, will have many benefits. In particular, it will induce efficient capacity planning—which has been the real problem in the past (not inefficient dispatch) and which is where the real opportunities for future efficiency gains lie. It will also encourage demand-side participation in peaking “reserves”, and forward contracting for risk protection and expansion financing, both of which also reduce generation market power. Independent system operator (ISO) planners and regulatory agencies should concentrate more attention on encouraging demand-side participation and forward contracting, and less on the sufficiency of physical reserves or on customer protection against possible high market prices.
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References
See Jacques H. Dreze [ 1964 ], “Some Postwar Contributions of French Economists to Theory and Public Policy,” 54 American Economic Review (June):1–64, for a good summary in English of Boiteux’s work.
It is conceivable that certain customers may lack the means to purchase devices that would insulate them from expensive on-peak consumption of commodity power. Their needs for reliability could be covered with special subsidies that do not alter the mode of restructuring recommended herein.
At the time of this writing yet another article (Robert J. Michaels [ 1997 ], “MW Gamble: The Missing Market for Capacity,” The Electricity Journal (December): 5664) has appeared espousing the “uniqueness” of electricity and the risks of inadequate future capacity under a deregulated market. We feel that it is ironic that Michaels claims that the old, regulated system generated an “efficient mix of energy and capacity, regulated to be priced as if it were in a competitive environment.” To the contrary, regulators are pursuing restructuring precisely because past capacity decisions based on uniform reliability criteria have not produced an economical supply mix. The financial indemnification approach t o motivating reliability is exactly alien to the rules and incentives used by commodity futures markets to assure liquidity and compensation for contract default.
The curves labeled demand in the figures should be interpreted as consisting of demand plus losses and operating revenues.
Simulations were performed with the IREMM model of production costing and trading. It uses derated capacity and monthly load duration curves, with local areas dispatched first to serve their own loads and trading occurring with marginal resources across all interconnected regions. Interconnections are based on NERC summer total transfer capability ratings, and wheeling charges are based on FERC filings or equivalent cost-based rates derived from FERC Form 1 transmission data. This work is discussed in detail in Electric Utility Restructuring Impacts on Fuels—Analyzing Off-Peak Conditions ( Palo Alto, CA: Electric Power Research Institute, 1998 ).
To the extent that the 10–15 percent savings occur, it will be because of stranded cost disallowances, which of course are not efficiency gains, just zero-sum wealth transfers.
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For the integration of demand bidding with supply dispatch see Fred C. Schweppe, Michael C. Caramanis, Richard D. Tabors, and Roger E. Bohn [ 1988 ], Spot Pricing of Electricity (Boston: Kluwer Academic Publishers). For discussion of curtailable demand prioritization see Hung-po Chao and Stephen Peck [1997], “An Institutional Design for an Electricity Contract Market with Central Dispatch,” Energy Journal 18 (1): 85–110.
As a bidding strategy, it would be feasible and profit-increasing to bid the variable cost of the unit most likely to be just above you in the dispatch ladder. For most hours in most market areas in the U.S., this next unit is likely to be very close in price, as the supply curve is almost continuous. As peak conditions are approached, the steepness of the curve and the sparsity of competitors may make this a more meaningful profit-seeking strategy of the competing parties.
This range assumes 33–50 percent debt financing and 20 year capital recovery, with the cost of equity at 14–15 percent. The “1 day in 10 years” LOLP standard that many pools have applied for planning reserves is often associated (depending on load shapes and other factors) with 4–20 hours per year of expected unserved load. It is over this many hours that the fixed costs of the marginal peaker would have to be recovered if it were to remain viable. Of course, a new peaker is very likely to have an efficiency much greater than the older units in a market area (i.e.,much better heat rate), so it is unlikely that the full costs of a CT will set the marginal value of capacity in a region. That is, any new CT will offset some of its fixed costs with inframarginal profits. Nonetheless, the truly marginal unit will have to recover some of its fixed costs in its per kWh bid, and the premium over variable costs could be quite large.
Steven Schleimer [ 1997 ], “Market Power Analysis in Support of PGandE’s Application for Market-Based Rates Before the FERC,” presentation to the Energy Modeling Forum, Stanford University, January 23.
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Blaise Allaz and Jean-L.C. Vila [ 1993 ], “Cournot Competition, Forward Markets and Efficiency,” 59 Journal of Economic Theory. 1–16.. See also Richard Green [1996] “The Electricity Contract Market” Cambridge University, U.K., preprint May, 1996. l t should be stressed that the above authors are addressing oligopoly situations; their results would not apply in a market with a single dominant player.
The above discussion of one-part pricing applies to generation because scale economies are not a major problem. This is not the case for transmission, which means that you may still need two-part pricing with a large part of the transmission infrastructure cost being recovered via some form of “fixed charge” (possibly a long run take-or-pay TCC). At the retail, or even wholesale, level these charges may well be converted into a peak consumption charge, though, and this can cause unfortunate distortions. A pure one-part tariff system is not necessarily ideal at all levels in the system. See E.G. Read [1998b], “Transmission Pricing in New Zealand,” forthcoming in Utilities Policy,for a detailed discussion of this issue. See also, Richard Green [1996], The Electricity Contract Market, Cambridge University, U.K May 1996 (preprint).
R.R. Austria, T.I. Leksan, W.R. Puntel, and J.R. Willi [ 1997 ], “Final Report Phase 1: Operating Reliability Requirements Study” (July 18), PTI Report No. R53–97 (Schenectady: NY: Power Technologies, Inc.).
The nature and history of the New Zealand electricity system is discussed by J.G. Culy, E.G. Read and B. Wright [ 1996 ], “Structure and Regulation of the New Zealand Electricity Sector,” in R. Gilbert and E. Kahn (eds.), International Comparison of Electricity Regulation (Cambridge University Press), p 312–365, while current arrangements and recent experience are covered by E.G. Read [1998a], “Electricity Sector Reform in New Zealand: Lessons from the Last Decade,” forthcoming Pacific Asia Journal of Energy, from which this summary is derived. E.G. Read [1998b], ‘Transmission Pricing in New Zealand,“ forthcoming in Utilities Policy. E.G. Read and D.P.M. Sell [1987], A Framework for Electricity Pricing, Arthur Young report released by the Electricity Corporation of New Zealand, Wellington.
Read [1998b] argues that capacity elements are still important in the transmission pricing arrangements, reflecting the prevalence of scale economies in that sector, although those capacity elements should properly be expressed in the form of long term transmission congestion contracts.
In fact the market structure adopted here was a natural extension to the way in which ECNZ’s costing model had been constructed. Since hydro was typically “on the margin,” the SRMC prices were themselves determined by a reservoir management model, which effectively calculated the “option value” of a unit of water as the expected value of that water, if stored to avoid the cost of thermal fuel, or shortage, at some future date.
See L.E. Ruff [ 1992 ], “Competitive Electricity Markets: Economic Logic and Practical Implementation” in Coping with the Energy Future: Markets and Regulations, Proceedings of the International Association of Energy Economists, Tours, France, for a description of the kind of market structure that New Zealand may pursue eventually.
See M.E. Bergara and P.T. Spiller [ 1997 ], “The Introduction of Direct Access in New Zealand’s Electricity Markets” in A. Lapointe, P.-O Pineau and G. Zaccour (eds.), Proceedings of the International Workshop on Deregulation of Electric Utilities, Montreal, pp. 253–274.
Most domestic water heating systems are electric, with a substantial storage tank and remote control systems allowing the local power company to determine when heating will occur. “Night storage” heating is also common, and can be controlled in a similar fashion.
This supply/demand asymmetry in dispatch and final pricing is less than ideal, and seems likely to prove inadequate, should there be a repeat of the 1992 crisis. Normally though, this is a reasonable approximation, given that demand can only react to ex ante price projections, and this reaction is reflected in the loads to be met by real time dispatch.
WEMS [ 1992 ] Towards a Competitive Wholesale Electricity Market: Conclusions and Recommended Approach, Wholesale Electricity Market Study, Final Report, Wellington, New Zealand.
See T.J. Scott and E.G. Read [1996], “Modeling Hydro Reservoir Operation in a Deregulated Electricity Sector,” International Transactions in Operations Research,3(3–4): 209, 221.
Hedging between those reference nodes and local nodes may be obtained from Trans Power, but this is not compulsory, and many participants, who are only exposed to relatively minor price differentials due to losses, may operate without any such cover.
E.G. Read, G.R. Drayton-Bright and B.J. Ring [ 1997 ], “An Integrated Energy/Reserve Market for New Zealand” in A. Lapointe, P.-O Pineau and G. Zaccour (eds.), Proceedings of the International Workshop on Deregulation of Electric Utilities, Montreal, pp. 275–291.
The grounds that purchasers in the wholesale market may not really represent the interests of small consumers who have insufficient choice, or information, to judge the creditworthiness of competing suppliers in the event of a crisis. Such arrangements were seen to be equivalent to the prudential requirements placed on financial institutions involved in what are essentially similar types of transaction. 32Frank C. Graves and James A. Read, Jr. [1997], “Capacity Prices in a Competitive Environment,” Chapter 7 in The Virtual Utility,Shimon Awerbuch and Alistair Preston (eds.) (Boston: Kluwer Academic Publishers): 175–192. Frank C. Graves [1997], “Capacity Prices in a Competitive Power Market,” presentation, IEEE PES Summer Meeting (July), Berlin, Germany.
Reliability Assurance Agreement among Load Serving Entities in the PJM Control Area, June 2, 1997. William W. Hogan [1997], Report on the Proposal to Restructure the New York Electricity Market (January 31 ).
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Graves, F.C., Read, E.G., Hanser, P.Q., Earle, R.L. (1998). One-Part Markets for Electric Power: Ensuring the Benefits of Competition. In: Power Systems Restructuring. The Springer International Series in Engineering and Computer Science. Springer, Boston, MA. https://doi.org/10.1007/978-1-4757-2883-5_7
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